The present invention relates to drilling, drill-in, and completion fluids, preferably water-base fluids, with good shale encapsulation properties resulting from the presence of calcium chloride and a low molecular weight, low charge cationic polyacrylamide copolymer.
Fluids used during drilling operations include xe2x80x9cdrilling,xe2x80x9d xe2x80x9cdrill-in,xe2x80x9d and xe2x80x9ccompletionxe2x80x9d fluids. A xe2x80x9cdrill-inxe2x80x9d fluid is pumped through the drill pipe while drilling through the xe2x80x9cpayzone,xe2x80x9d or the zone believed to hold recoverable oil or gas. A xe2x80x9cdrilling fluidxe2x80x9d is used to drill a borehole through the earth to reach the payzone. Typically a drilling mud is circulated down through the drill pipe, out the drill bit, and back up to the surface through the annulus between the drill pipe and the borehole wall. The drilling fluid has a number of purposes, including cooling and lubricating the bit, carrying the cuttings from the hole to the surface, and exerting a hydrostatic pressure against the borehole wall to prevent the flow of fluids from the surrounding formation into the borehole. A xe2x80x9ccompletion fluidxe2x80x9d is used to protect the xe2x80x9cpayzonexe2x80x9d during the completion phase of the well.
Fluids in which water is the continuous phase provide for a fast drilling rate, and are ecologically favored over fluids in which oil is the continuous phase. Unfortunately, the walls of a wellbore frequently are composed at least in part of shale, and when exposed to water, many shales swell, slough, or spall to the extent that they may even prevent further operation of the wellbore. Shale also may slough off during gravel transport in open-hole completion, mix with the gravel, and reduce the productivity of the well by choking off the permeability of the gravel pack. The sloughing also may cause screen blinding.
Brines have long been used in the formulation of drilling fluids to take advantage of their density and their inhibitive characteristics. Clay chemistry has shown us that cationic base exchange with the negatively charged clay minerals commonly found in shale formations, limits their ability to hydrate, soften, and swell, thereby rendering them more stable in the presence of water based fluids.
Monovalent salts, such as NaCl or KCl, have long been used as make up water for drilling fluids. In the past, NaCl or KCl have provided a limited inhibitive environment for drilling hydratable shales in many areas. In offshore drilling, seawaterxe2x80x94a complex mixture of various salts which is readily availablexe2x80x94has frequently been used in formulating drilling mud.
Today, technological advances in the design of drilling equipment has resulted in increased penetration rates for better drilling economics. The performance of the monovalent salt systems has not been able to maintain pace with new advances in drilling technology. The need for improved drilling mud systems saw the application of oil mud systems and development of synthetic systems to meet these challenges. However, increasing environmental regulation has limited the application of these systems.
Divalent salts are known to provide an added inhibitive benefit for drilling water sensitive shales. Divalent salts are capable of developing a strong bond with and between active clay platelets in these shales, thereby further limiting the volume of hydration water that can become a part of the clay, causing it to become soft, pliable, and sticky, resulting in problems with mechanical drilling equipment and drilling fluid control. One of the most available and economical divalent salt systems is CaCl2. CaCl2 systems have been around for many years, and the inhibitive characteristics of the calcium ion are well known.
Water-soluble polymers are used to thicken water-base fluids, and in part to synergistically stabilize shale. The water-soluble polymers provide the viscosity necessary to lift drilled solids from the wellbore, and tend to improve drilling rates.
Unfortunately, fluids which have shown promise in increasing the rate of penetration through shales also have tended to increase screen blinding, which can lead to huge losses of mud, with loss of rig time and high fluid costs. Water base fluids are needed which can achieve a high rate of penetration without screen blinding.
The present invention provides a drilling system fluid comprising water as a continuous phase, a first amount of a divalent metal salt, and a quantity of a polyacrylamide copolymer, wherein the amount of the divalent salt and the quantity of polyacrylamide copolymer are sufficient to produce a rate of penetration approaching that achieved using a synthetic oil-based drilling system fluid while preventing substantial screen blinding. In a preferred embodiment, the continuous phase also comprises a second amount of a monovalent salt effective to increase gas hydrate suppression and decrease density when compared to a fluid consisting essentially of only a divalent salt in the absence of the monovalent salt.
The present invention involves formulating aqueous-base drilling fluids to stabilize shale encountered during drilling. The water base fluids of the present invention comprise a combination of a suitable divalent salt, a suitable monovalent salt and a relatively low charge cationic, low molecular weight polyacrylamide copolymer. In a preferred embodiment, the divalent salt is calcium chloride and the monovalent salt is sodium chloride. This fluid composition provides a rate of penetration that approaches synthetic oil-based systems, and also provides good shale encapsulating properties for control of gumbo shale without substantial screen blinding. For purposes of the present application, the term xe2x80x9csubstantial screen blindingxe2x80x9d is defined as the formation of a mat of undissolved or dispersed polymer on the shaker screen, which blocks passage of the hole fluid through the shaker screen, causing the hole fluid to overflow the shaker screen.
The polyacrylamide copolymers of the present invention may be used in substantially any drilling, drill-in, or completion fluid. As used herein, the term xe2x80x9cdrilling fluidxe2x80x9d or xe2x80x9cdrilling fluidsxe2x80x9d shall be interpreted to refer to any one of these kinds of fluids. Preferred drilling fluids have water as a continuous phase.
Preferred drilling fluids comprise a mixture of salts consisting of brines comprising about 5 wt % to about 20 wt %, preferably about 15 wt % of the divalent salt, most preferably calcium chloride and about 0 lb/bbl to about 70 lb/bbl, preferably about 40 lb/bbl to about 70 lb/bbl, most preferably 50 lb/bbl of the monovalent salt, preferably sodium chloride. The fluids can contain substantially any suitable salts, suitable divalent salts include, but are not necessarily limited to salts based on metals, such as calcium, magnesium, zinc, and aluminum. Suitable monovalent salts include but are not necessarily limited to those based on metals such as sodium, potassium, cesium, and lithium. The salt may contain substantially any anions, with preferred anions including, but not necessarily limited to chlorides, bromides, formates, propionates, sulfates, acetates, carbonates, and nitrates. A preferred anion is chlorine. Preferred brines comprise calcium chloride. Sodium chloride is typically added to the drilling fluid after the calcium chloride brine.
The water-base drilling fluids contain xe2x80x9cwater-soluble polymers,xe2x80x9d defined as polymers that are capable of viscosifying a drilling fluid and/or providing filtration control for a drilling fluid. Preferred viscosifiers and filtration control agents are XAN-PLEX(trademark) D, BIO-PAQ(trademark) and/or BIOLOSE(trademark), all of which are commercially available from Baker Hughes INTEQ.
The drilling fluids of the present invention also contain xe2x80x9cpolyacrylamide copolymersxe2x80x9d to provide shale inhibition. The term xe2x80x9cpolyacrylamide copolymersxe2x80x9d is defined herein to refer to cationic polyacrylamide copolymers having a relatively low molecular weight and a relatively low charge. The term xe2x80x9clow molecular weightxe2x80x9d is defined to mean copolymer units having from about 500,000 to 4 million mole weight, preferably from about 800,000 to about 1 million mole weight. The term xe2x80x9clow chargexe2x80x9d is defined to mean from about 1 mol % to about 15 mol % of a cationic monomer charge, preferably about 5 mol % to about 10 mol % cationic monomer charge. The cationic monomer charge may be from about 1 to about 4. Without limiting the present invention to a particular mechanism of action, it is believed that cations in the polyacrylamide copolymer adsorb onto the negatively charged surface of the shale, forming a gelatinous protective layer which inhibits degradation of the shale.
Suitable polyacrylamide copolymers have the following general structure: 
wherein R and R1 are selected from the group consisting of hydrogen, acrylamide groups, acrylate groups, polyacrylamide groups, and polyacrylate groups, and copolymers thereof; R2 is selected from the group consisting individually of hydrogen, and alkyl groups, preferably methyl and ethyl groups; and, R3 is selected from the group consisting of ester groups comprising a cationic group and amide groups comprising at least one cationic group, wherein said cationic group comprises a charge in the range of from about +1 to about +4; and, n is at least 1. A preferred cationic group has the following general structure: 
Suitable polyacrylamide copolymers are commercially available from a number of sources, and include but are not necessarily limited to HYPERDRILL CP-904L(trademark), available from Hychem, Inc., Tampa, Fla., and SUPERFLOC(trademark), available from Cytec Industries, West Patterson, N.J. A preferred polyacrylamide copolymer is DFE-243, which comprises partially hydrolyzed polyacrylamide (PHPA) and trimethylaminoethyl acrylate, which has about a 800,000 to 1 million molecular weight and about a 5% to about a 10% cationic charge density. DFE-243 is commercially available from Baker Hughes INTEQ.
In order to achieve the desired shale stabilization, the fluid should contain from about 0.05 wt % to about 0.5 wt % of the polyacrylamide copolymer, preferably at least about 0.08 wt %, most preferably at least about 0.3 wt %,of the polyacrylamide copolymer.
Bridging or weighting agents preferably should be added to bridge the pores in the formation. Suitable bridging or weighting agents include, but are not necessarily limited to ground marble or calcium carbonate particles, such as MIL-CARB, available from Baker Hughes INTEQ. Preferred calcium carbonate particles have a mean particle size of about 30 microns. Calcium carbonate has the advantage that it is acid soluble, and therefore can be removed from the formation by acid flushing. If calcium carbonate is used as the bridging agent, then from about 10 to about 50 pounds should be used per barrel of brine.
Preferred polyacrylamide copolymer containing drilling fluids are xe2x80x9cnon-toxic.xe2x80x9d As used herein, the term xe2x80x9cnon-toxicxe2x80x9d is defined to mean that a material meets the applicable EPA requirements for discharge into U.S. waters. Currently, a drilling fluid must have an LC50 (lethal concentration where 50% of the organisms are killed) of 30,000 parts per million (ppm) suspended particulate phase (SPP) or higher to meet the EPA standards. The mysid shrimp toxicity test for a drilling fluid according to the present invention containing 1.0-1.25 lb/bbl DICAP(trademark) resulted in an LC50 of 120,000 ppm of the suspended particulate phase (SPP)xe2x80x944 times the minimum EPA standard for discharge into coastal waters. The toxicity tests for the 0.1-1.5 lb/bbl DFE-243 resulted in an LC50 of 150,000-300,000 ppm of the SPP.
In order to prepare the foregoing drilling fluids, fresh water is placed in a mixing hopper and the following are added: the viscosifying polymer (XAN-PLEX(trademark) D, available from Baker Hughes, INTEQ), and the filtration control polymer (BIO-PAQ(trademark) and/or BIOLOSE(trademark), also available from Baker Hughes INTEQ). The mixture is agitated well before adding the calcium chloride brine and the sodium chloride. XAN-PLEX(trademark) D and the polyacrylamide copolymer should not be added at the same time. A preferred mixer to prevent xe2x80x9cfish-eyeingxe2x80x9d of the polymers is a shear device similar to Gauthier""s Brothers, POLYGATOR GBR. The mixing equipment should be capable of very good agitation at high shear to disperse all of the ingredientsxe2x80x94particularly the polymeric ingredientsxe2x80x94to achieve a final smooth blend. Preferably, the mixing hopper should be in-line so the sheared polymer goes directly into the mixing tank as opposed to using a low shear hopper and then xe2x80x9cre-circulatingxe2x80x9d through the high shear device. The mixing pits also should have an impeller for proper mixing and dispersion of the polymers.
Preferably, calcium chloride or a 15 wt % calcium chloride brine is added to the mixture first, then NaCl is added to the mixture. After sufficient agitation, the polyacrylamide copolymer is sifted into the mixture with good agitation. After sufficient agitation, MIL-CARB(trademark), MIL-BAR(trademark), and any other additives, such as gas hydrate suppressors, are added to the mixture with agitation, as needed. To minimize sag of MIL-CARB(trademark) and MIL-BAR(trademark) during storage or transport, 3 lb/bbl of SALT WATER GEL(copyright) may be added and sheared well before transferring the fluid to the mixing pit. Before measuring the pH of the mud, the mud should be diluted in a ratio of 9 parts deionized water to 1 part mud and thoroughly mixed.
If cement is to be drilled using the fluid of the invention, the fluid should be protected from cement contamination. In order to prevent cement contamination, the acidic pretreatment product is added before any green cement (MIL-CARB(trademark) or MIL-BAR(trademark)) is incorporated into the system to prevent pH effects on the biopolymer or filtration control agent. Citric acid powder (to reduce pH to xc2x17) is recommended as a pretreatment product and can be used more safely than commonly used liquid acetic acid to control mud pH while drilling cement.
As much xe2x80x9cqualityxe2x80x9d premix mud should be prepared at the mixing plant as possible so that the mud engineers on the rig can keep up with mud volume requirements of large diameter/high rate of penetration drilling operations. Otherwise, the polymers may be poorly dispersed, resulting in severe xe2x80x9cfish-eyeingxe2x80x9d and resultant screening problems.
The invention also is directed to a method for increasing shale stability of a drilling fluid containing the claimed brine by mixing a polyacrylamide copolymer with the brine, either before using the brine to formulate a drilling fluid, or during operation as an additive to the drilling fluid. If the polyacrylamide copolymer is used as an additive, an amount of copolymer preferably is added in increments of about 0.25 lb/bbl in order to achieve a surplus of polyacrylamide polymer in the filtrate of about 0.3 to about 1.0 lb/bbl.
The invention will be more clearly understood with reference to the following examples, which are illustrative only and should not be construed as limiting the present invention. In the following Examples, the following materials are trademarked products available from Baker Hughes INTEQ: XAN-PLEX(trademark) D; DICAP(trademark); MIL-BAR(trademark); MIL-CARB(trademark); BIO-PAQ(trademark); and BIOLOSE(trademark). REV-DUST(trademark) is a trademark for a product which may be obtained from Mil-White Company, Houston, Tex. xe2x80x9cEncapsulator Dxe2x80x9d is a commercially available shale inhibitor used for comparative purposes.
Early laboratory investigations centered around the evaluation of primary viscosifiers for the proposed fluid. Further laboratory testing included an evaluation of XAN-VIS (clarified xanthan gum with greater calcium tolerance) vs. XAN-PLEX(trademark) D polymer. Shale inhibition tests used shale wafers constructed from GOM xe2x80x9cgumboxe2x80x9d and a pelletized bentonite product, xe2x80x9cHole Plugxe2x80x9d. Additional testing included an examination of the addition of cement treatment additives to prevent the detrimental effects of increased pH on the solubility or cross-linking of biopolymers.
The following laboratory equipment was used in conducting the experiments described in the examples:
Mixer: Prince-Castle equipped with FANN B-7210 Blade or equivalent (3.0 mm (0.5xc2x1mm pitch)
Baffled, 2 liter, stainless conical mixing cups (Prototypes) from INTEQ-Houston Fluids
Mixer: Waring Blender with standard blade and mixing cup
Tachometer: hand held Model CT800 described in the RS Components Catalog or equivalent
Mixing Cup: 1 or 2 liter, conical cups, OFI Model 110-50 or equivalent
Balance: precision of 0.01 g (2000 g capacity)
Thermometer: precision of xc2x11xc2x0 F. or xc2x10.5xc2x0 C.
Thermometer-metal 1xc2xexe2x80x3 dial, 8xe2x80x3 stem Cole Palmer H08080-04 precision xc2x11% of dial range
Motor-Driven Direct Indicating Viscometer as referenced in API RP 13-B-1, 1st Edition, June 1990, Par. 2.4
Filter Press as referenced in API RP 13B-1, 1st Edition, June 1990, section 3.2
Filter Press as referenced in API RP 13B-1, 1st Edition, June 1990, section 3.4
Aging Cells as referenced in API Recommended Practice 13-I, 5th Edition, Jun. 1, 1995, section 19
Oven: regulated to desired temperature xc2x15xc2x0 F. (xc2x13xc2x0 C.). Preferred ovens are digitally controlled with 1) dynamic air circulation, 2) temperature recorders and 3) data acquisition system
Glass jars for aging at temperatures  less than 160xc2x0 F. (450 ml capacity)
The following mixing procedures were used in the following examples:
1. Mixer: Prince-Castle with FANN B7210 or equivalent blade
2. Mixing volume: 2 laboratory barrels (700 mls)
3. Total mixing time: 1 hour
4. Mixing speed: 9000 rpm
5. Mixing Temperature: Ambient to 150xc2x0 F.
6. Order of addition: An important element of all laboratory testing included a product order of addition and mixing times required for complete product dispersion and/or solubility. The following describes the order of addition, and the mixing time for each product used in testing the formulations:
Component/Time, min/Product
Water/0 min/liquid phase
Viscosifier/10 min/XAN-PLEX D
Fluid Loss Control/10 min/BIO-LOSE(trademark)
11.6 lb/gal CaCl2 brine/1 min/liquid phase
Shale Stabilizer/30 min/DFE-241/242, Encapsulator D
Bridging material/5min/MIL-CARB
Contaminant/4 min/Rev Dust, cement
Notes
XAN-PLEX(trademark) D was selected as the most cost effective viscosifier. Both Kelco XCD and XAN-PLEX(trademark) D were used in all other tests.
Baffled mixing cups will reduce spillage and increase shear.
If mixing time for total product additions is less than the total mixing time, continue mixing fluid after the last product addition until the total mixing time has been reached.
After heat aging, mix fluid at 6000 rpm for 5 minutes prior to testing.
Use defoamer as necessary.
Inhibition tests included both the Hole-Plug and xe2x80x9cgumbo waferxe2x80x9d tests.